Coiled tubing storage, deployment, and control

Abstract

A carousel assembly for managing a length of wellbore tubing includes a stationary base and a hub rotatable relative to the stationary base about a central axis. The carousel assembly is configured to, as the hub rotates, pay out the length of tubing from the hub to a wellhead. The carousel assembly further includes a hydraulic swivel and a connector. The hydraulic swivel is configured to supply, as the hub rotates, fluid to a central bore of the length of tubing, and the connector is configured to convey, as the hub rotates, a signal to a communication line extending axially along the length of tubing.

Description

F&R Ref. 50511 -0094 WO 1COILED TUBING STORAGE, DEPLOYMENT, AND CONTROLCLAIM OF PRIORITY

[0001] This application claims the benefit of U.S. Provisional Application Serial No. 63 / 700,355, filed on September 27, 2024, and U.S. Provisional Application Serial No. 63 / 792,219, filed on April 21, 2025. The entire contents of the foregoing are incorporated herein by reference.TECHNICAL FIELD

[0002] This disclosure relates to storage, deployment, and control of coiled tubing for drilling, completion, or operation of wellbores and related operational systems and controls.BACKGROUND

[0003] Coiled tubing can be utilized for the drilling of deep wells. Storage and deployment of coiled tubing can create operational challenges that can increase costs and complexity of the operations and the risks to personnel and the environment.SUMMARY

[0004] Certain aspects of the present disclosure encompass a carousel assembly for managing a length of wellbore tubing. The carousel assembly includes a stationary base and a hub rotatable relative to the stationary base about a central axis. The carousel assembly is configured to, as the hub rotates, pay out the length of tubing from the hub to a wellhead. The carousel assembly further includes a hydraulic swivel and a connector. The hydraulic swivel is configured to supply, as the hub rotates, fluid to a central bore of the length of tubing, and the connector is configured to convey, as the hub rotates, a signal to a communication line extending axially along the length of tubing.

[0005] Certain aspects of the present disclosure encompass a well system that includes a length of wellbore tubing configured to be disposed in a wellbore via a wellhead and a carousel assembly within which a portion of the length of wellbore tubing is disposed. The carousel assembly includes a stationary base and a hub rotatable relative to the stationary base about a central axis. The carousel assembly configured to, as the hub rotates, pay out the length of tubing from the hubF&R Ref. 50511 -0094 WO1 to a wellhead. The carousel assembly further includes a hydraulic swivel and a connector. The hydraulic swivel is configured to supply, as the hub rotates, fluid to a central bore of the length of tubing, and the connector is configured to convey, as the hub rotates, a signal to a communication line extending axially along the length of tubing.

[0006] Certain aspects of the present disclosure encompass a method of well operations. The method includes disposing a portion of a length of tubing in a wellbore through a wellhead from a carousel assembly includes a stationary base and a hub rotatable relative to the stationary base about a central axis. The carousel assembly configured to, as the hub rotates, pay out the length of tubing from the hub to a wellhead. The carousel assembly further includes a hydraulic swivel and a connector. The method further includes, as the hub rotates, flowing fluid through the central bore via the hydraulic swivel and conveying a signal through the communication line.

[0007] The present disclosure can encompass some, all, or none of the following features. The hub can be a cage. The communication line can be configured to convey a signal to an apparatus disposed on a downhole portion of the length of tubing. The apparatus disposed on the downhole portion is a contactless drill bit. The connector can be a first connector, the signal is a first signal, and the communication line can be a first communication line, and wherein the carousel assembly further comprises a second connector configured to convey, as the hub rotates, a second signal to a second communication line extending axially along the length of tubing. The tubing is composite coiled tubing. The communication line can comprise an electrical conveyance and the signal comprises an electrical signal. The connector can comprise an electrical contact ring. The communication line can comprise a capillary tubing. The communication line can comprise an optical fiber. The central axis can be substantially vertical. The hub can rotates on rollers disposed between the stationary base and the hub. The system can be controlled by an autonomous control system.

[0008] The present disclosure can encompass some, none, or all of the following features. The length of tubing includes segments of tubing can be attached by a connector having a diameter greater than a diameter of the segments of tubing. The system can further include a stripper assembly disposed between the hub and the wellhead, the stripper assembly comprising a first stripper spaced apart from a second stripper. The method can include dilating the first stripper to permit the connector to pass through the first stripper while the second stripper seals about aF&R Ref. 50511 -0094 WO1 peripheral surface of the length of tubing and thence, as the first stripper then closes to seal about the peripheral surface, dilate the second stripper to permit the connector to pass through the second stripper. The method can include dilating the second stripper to permit the connector to pass through the second stripper while the first stripper seals about a peripheral surface of the length of tubing; and thence, as the second stripper then closes to seal about the peripheral surface, dilating the first stripper to permit the connector to pass through the first stripper. The system can further includes an injector assembly disposed between the hub and the wellhead, the injector assembly comprising a first injector spaced apart from a second injector. The method can include dilating the first injector to permit the connector to pass through the injector while the second injector maintains the load of the tubing by contacting a peripheral surface of the tubing and thence, as the first injector then closes to maintains a load of the tubing by contacting a peripheral surface of the tubing, dilate the second injector to permit the connector to pass through the second injector. The method can include dilating the second injector to permit the connector to pass through the second injector while the first injector maintains the load of the tubing by contacting a peripheral surface of the tubing; and thence, as the second injector then closes to maintains the load of the tubing by contacting a peripheral surface of the tubing, dilating the first injector to permit the connector to pass through the first injector.F&R Ref. 50511 -0094 WO1DESCRIPTION OF DRAWINGS

[0009] FIG. 1 is a schematic illustration of a well system in accordance with the concepts herein.

[0010] FIGS. 2 A and 2B are schematic illustrations of carousel assembly in accordance with the concepts herein.

[0011] FIG. 3 is a schematic illustration of a handling and control system of a well system in accordance with the concepts herein.

[0012] The drawings are not to scale.F&R Ref. 50511 -0094 WO 1DETAILED DESCRIPTION

[0013] Composite coiled tubing drilling strings can be used to drill deep geothermal wells. Composite materials such as carbon fiber in a thermoplastic polyvinyldifluoride (PVDF) matrix or carbon fiber in a polyetheretherkeytone (PEEK) matrix are typically thermally limited to under 200 °C which may be lower than the temperature of the rock to be drilled. In accordance with instances of the present disclosure, systems and processes are employed to thermally protect the composite drilling strings, in which excess drilling fluid can be circulated from surface to maintain the wellbore annulus at ~120°C or below. Drilling mud may be circulated at rates of 3000L / min - 5000L / min to provide the cooling. In some instances, drilling strings with a large flow passage and / or the capability to withstand high circulation pressures may be used. For example, the friction pressure losses in coiled tubing drilling strings in excess of 15,000m in length may prompt the use of circulation pressures of about 69 MPa or greater in order to circulate fluid along the coiled tubing drilling string.

[0014] In some instances, and based on the need for high flow rates, the insulative properties, the high-pressure capacity needed to promote fluid flow, some composite string designs can have an approximate diameter of 150mm with an approximate wall thickness of 25mm. In general, large diameter composite coiled tubing presents a number of operational and handling challenges.

[0015] On a conventional coiled tubing rig, coiled tubing can be spooled onto a reel. In accordance with aspects of this disclosure, coiled tubing is managed via a carousel with a rotating hub. The hub includes a hydraulic swivel to supply fluid to central bore of the as the hub rotates. The hub further includes more electrical contacts to provide an electrical signal to a communication line extending through tubing to components along or at the end of the tubing.

[0016] to the use of a conventional reel can present operational and, safety concerns associated with the energy stored in the composite coiled tubing as it is elastically wrapped around the reel. For example, coiled tubing can behave as an elastic body that at least partly recovers its original (e.g., straight) shape after being bent to wrap around a reel, and can act like a torsion spring that can unwind in a hazardous manner if not held in place. In accordance with aspects of this disclosure, the rotating hub is a cage that substantially surrounds the radial periphery of the composite coiled tubing, so that the composite coiled tubing can be safely stored without the risk of it rapidly unwinding if the string parts at surface.F&R Ref. 50511 -0094 WO1

[0017] In accordance with aspects of this disclosure, the carousel can be a component of a drilling system that can include an automated control system. The control system can allow for management of annular temperature (as opposed to merely internal fluid temperatures) and can support circulation operations and complex thermal staging. The control system can employs a composite-specific digital twin, enabling predictive control.

[0018] The aspects of the present disclosure can be used for, for example, geothermal drilling and completions with composite coiled tubing, HPHT well intervention, coiled tubing stimulation, forward or reverse circulation jobs, operations requiring precise thermal management of the annular environment, and advanced coiled-tubing steering and tool deployment in extended-reach wells.

[0019] Whereas existing solutions may rely on surface-only measurements (reel counters, hookload), linear steel-based tension / stretch models, and passive thermal monitoring, aspects of the present disclosure are directed to using real-time, downhole and surface sensing (tension, pressure, inner / outer temperature), integrating a live digital twin that reflects composite laminate behavior, enabling closed-loop control over all key equipment systems, and supporting dynamic responses during transient events (flow loss, temp surges).

[0020] FIG. 1 depicts an instance of a well system 100 in accordance with the concepts herein. System 100 includes a wellhead 110 at the surface location where a wellbore 111 is drilled into a subterranean zone. Well system in some instances can be a well drilling system using coiled tubing 120 as a drill string, using a drill bit 113 at the downhole end of coiled tubing 120. Affixed atop wellhead 110 is a pressure stack 150 which can include valves, preventers, and other equipment to maintain pressure control of well 111 during drilling operations. In some instances, above pressure stack 150 is tower assembly 152 which in some instances comprises an injector (or tensioner) assembly 154 and a stripper assembly 156, each of which is described in greater detail below.

[0021] In some instances, drill bit 113 is a contact-type drilling bit, such as a polycrystalline diamond compact (PDC) drilling bit, tri-cone drilling bit, rotary drilling bit, and / or another type of drilling bit that relies on the bit contacting the rock and mechanically transmitting force to load the rock face (i.e., the end wall of the wellbore at which rock is being removed) break the rock, and thus drill. In other instances, the drilling bit can be a contactless drilling bit configured to break the rock at the rock face being drilled without requiring mechanical loading by contact betweenF&R Ref. 50511 -0094 WO1 the bit and the rock face. Examples of contactless drilling bits include bits for plasma drilling (such as the plasma drilling system developed by GA Drilling, A.S.), laser drilling (such as the laser drilling system developed by Foro Energy), microwave drilling (such as the microwave drilling system developed by Quaise, Inc.), thermal spallation drilling including supercritical water jetting or flame jets, electro-pulse drilling (such as the electro-pulse drilling systems developed by Tetra Corporation), and particle drilling (e.g., impacting the rock with particles entrained in fluid, such as the system developed by Particle Drilling Technologies, Inc.). Although, referred to as “contactless,” this descriptor is not meant to exclude systems where portions of a drilling bit may bump, brush against, or otherwise come into contact with the formation during the drilling process. For example, an electro-pulse drilling bit can still be considered a contactless drilling bit if the bit is configured to contact the rock such as to facilitate electrical transmission through the rock, because it does not rely on the bit contacting the rock and mechanically transmitting force to load the rock. In certain instances, the drilling bit can be a hybrid contact / contactless bit configured both for contactless and contact drilling. One example of a hybrid drilling bit includes a bit body with the cutting components of a contactless drilling bit (e.g., electro-pulse drilling bit, plasma drilling bit, water or flame jet, and / or other type of contactless drilling) arranged to perform the preliminary drilling or primary drilling and the cutting components of contact-type drilling bit, such as an array of cutters (e.g., PDC cutters and / or other type of cutters), arranged around the perimeter of the bit for cleaning and / or reaming (widening) the wellbore drilled by the contactless portion of the bit. Other examples of hybrid drilling bits are within the concepts herein.

[0022] In electro-pulse drilling systems, an electrocrushing bit is utilized that has multiple electrodes that generate high energy sparks to break formation material and thereby enable it to be cleared from the path of the drilling assembly. The bit can generate multiple sparks per second using a specified excitation current profile that causes a transient spark to form and arc through the most conducting portion of the rock face at the downhole end of the wellbore. The arc causes that portion of the rock face penetrated by the arc to disintegrate or fragment and be swept away by the flow of drilling fluid. Furthermore, in certain instances, the direction and characteristics of the arc can be modulated to control the specified drilling trajectory, such as, for example, described in U.S. Pat. App. Pub. No. US20230144083A1. In certain instances, a highly electrically resistive drilling fluid is utilized for such electro-pulse drilling. In certain instances, electrically resistiveF&R Ref. 50511 -0094 WO1 drilling fluid is not needed for electro-pulse drilling, and the drilling fluid can include aqueous fluids. Descriptions of some electro-pulse drilling bits, drilling fluids, and related systems and methods that can be used herein are found in, for example, U.S. Pat. No. 4,741,405, U.S. Pat. No. 9,027,669, U.S. Pat. No. 9,279,322, U.S. Pat. No. 10,060,195, U.S. Pat. Pub. No. 12000299562A1, and PCT patent applications WO 2008 / 003092, WO 2010 / 027866, WO 2014 / 008483, WO 2018 / 136033, and WO 1200 / 236189.

[0023] Carousel assembly 140 includes a hub 144 rotatable relative to a stationary base 142 about a central axis 146 (as described in greater detail in FIGS. 2A and 2B). As hub 144 rotates, a length of coiled tubing 120 is paid out from the hub 144 to hauler 137 and thence to Bowden tube (or guide) 112 which is configured to guide coiled tubing 120 into tower assembly 152.

[0024] In some instances of the present disclosure, a length of coiled tubing 120 may be comprised of multiple tubing segments 160 assembled together using one or more connectors 162. Coiled tubing 120 includes wall 122 defining a central bore 126 through which fluid (such as drilling fluid 128) can flow. Within central bore 126 and on wall 122 (or, in some instances, within wall 122), a communication line 124 runs along the central axis of coiled tubing 120 from (or substantially from) its first end to its second end, such that, when coiled tubing 120 is disposed in wellbore 111, communication line 124 can convey a signal (such as electrical energy to power (or a control or sensor signal to or from) a downhole apparatus (such as bit 113). In some instances communication line 124 is metallic wire or other electrical conveyance. In some instances communication line 124 is a capillary tubing, optical fiber, or other suitable communication line.

[0025] FIGS. 2A and 2B illustrate a carousel assembly in accordance with instances of the present disclosure. Carousel assembly 140 includes a hub 144 rotatable relative to stationary base 142. In the illustrated instance, hub 144 is a toroidal cage defined by inner wall 230 and outer wall 232 (each of which in the illustrated instance comprises vertical rods or posts) and sweeps 233 to retain tubing 120. As hub 144 rotates about axis 146, tubing 120 lays on sweeps 233 as it is coiled, building subsequent horizontal layers of tubing on or within hub 144. The inner wall 230 can in some instances have a radius exceeding the minimum bend radius of coiled tubing 120, and the outer wall 232 can have a radius exceeding the radius of the inner wall 230 Rollers 214 mounted at the interface of hub 144 and base 142 to enable low friction rotation of hub 144 about central axis 146. In some instances, instead of or in addition to rollers 214, a low friction surface - suchF&R Ref. 50511 -0094 WO 1 as Teflon pads - can be mounted at the interface of hub 144 and base 142. Hydraulic swivel 204 has a stationary inlet line 206 on a stationary section 250 with an inlet 208 and a outlet line 210 on rotatable section 252 with an outlet 212 that connects to an end of tubing 120 to supply fluid to central bore of tubing 120 as hub 144 rotates. One or more electrical contacts 220 are affixed to hub 144 and in contact with conductive rings 222 to provide an electrical signal to a communication line extending through tubing 120. In another instance of the present disclosure, conductive rings 222 can be mounted to the hub 144.

[0026] As noted above, in some instances of the present disclosure, a length of coiled tubing 120 may be comprised of multiple segments assembled together using one or more connectors 162. In some instances, connectors 162 may have an outside diameter larger than the outside diameter of the coiled tubing itself. Conventional coiled tubing stripper and injector assemblies may not accommodate coiled tubing strings with such discontinuities in the outside diameter. Accordingly, FIG. 3 illustrates an instance of injector (or tensioner) assembly 154 and stripper assembly 156 of tower assembly 152 that are configured to accommodate such diameter discontinuities. In the instance shown in FIG. 3, injector assembly 154 comprising a first injector 332 and a second injector 334 configured to grip and urge movement of a coiled tubing string in and out of a wellbore. First injector 332 and second injector 334 are can be spaced axially apart along the coiled tubing string and such that they can ‘hand off segments of coiled tubing 120 from one to another as the connectors pass through injector assembly 154 as it is run into the wellbore. For example, a traction section of one injector can be configured to spread apart to allow the connector to transit through, while the other injector maintains a grip on the peripheral surface of the coiled tubing string. More specifically, for example, as connector 162 approaches first injector 332, injector 332 dilates (i.e., the gripping members move away from the tubing) to allow the connector to pass through it, with the gripping elements of injector 334 remaining closed (i.e., in contact with and gripping the peripheral surface of the tubing). Once the connector has passed through dilated injector 332, injector 332 closes (i.e., the gripping elements move together to grip the peripheral surface of the tubing). As the tubing is pulled out of the wellbore, the sequence can be reversed; i.e., as connector 162 approaches second injector 334, injector 334 dilates to allow the connector to pass through it, with injector 332 remaining closed. Once the connector has passed through injector 334, injector 334 closes, as injector 332 dilates to allow connector 162 to pass. The twoF&R Ref. 50511 -0094 WO1 injectors can thus work in conjunction with the hauler (shown as 137 in FIG. 1) to maintain the appropriate amount of elastic tension in the carousel and safely pay out the composite coiled tubing to the injectors while maintaining an appropriate level of string tension between the hauler and the injectors and that the coiled tubing is under an appropriate amount of stress, and wraps tightly as required in or on hub 144, as it is bent elastically.

[0027] In the illustrated instance, stripper assembly 156 also includes a first stripper 342 and a second stripper 344 spaced axially apart along the coiled tubing string. As segments of coiled tubing 120 pass through stripper assembly 156 as it is run into the wellbore, sealing elements of one or both of strippers 342 and 344 pack off around the segment to provide a seal. As connector 162 approaches first stripper 342, the seal element of stripper 342 dilates to allow the connector to pass through it, with the elastic element of stripper 344 remaining closed. Once the connector has passed through the dilated sealing element of stripper 342 the sealing element of stripper 342 closes, maintaining fluidic and pressure isolation from the wellbore, as the sealing element of stripper 344 dilates to allow connector 162 to pass. In some instances stripper assembly 156 can include a coiled tubing pack-off or annular blow-out preventer. As the tubing is pulled out of the wellbore, the sequence can be reversed; i.e., as connector 162 approaches second stripper 344, the seal element of stripper 344 dilates to allow the connector to pass through it, with the elastic element of stripper 342 remaining closed. Once the connector has passed through the dilated sealing element of stripper 344 the sealing element of stripper 344 closes, maintaining fluidic and pressure isolation from the wellbore, as the sealing element of stripper 342 dilates to allow connector 162 to pass.

[0028] FIG. 3 also schematically illustrates power source 300 and fluid source 302 which can provide power and fluid to conductive rings 222 and fluid inlet 208 (described above in reference to FIGS. 2A and 2B), respectively. In the illustrated instance, system 100 further includes a control system 360 that can be autonomous and can control, for example, a subset of the operational parameters such as circulation rates for cooling of the coiled tubing string, coiled tubing injection and retrieval rates, weight on bit, and well control equipment. Circulation rates can be determined by a digital twin to the wellbore based on numeric modeling, real time sensor data from the rig, real time sensor data from instrumentation of the coiled tubing string, and real time sensor data from within the wellbore including the bottom hole assembly. In some instances,F&R Ref. 50511 -0094 WO1 control of operations by control system 360 can be automated, for example, based on sensors in the pressure control stack that detect the presence of a connector. In some instances, these sensors could be electromagnetic, optical, acoustic, or use other sensing technology well understood in industry.

[0029] In some instances control system 360 regulates the interaction of carousel assembly 140, the hauler 137, injector assembly 154, and stripper assembly 156. The control system can be based on a digital twin to the coiled tubing string based on numeric modeling, real time sensor data from the rig, real time sensor data from instrumentation of the coiled tubing string, and real time sensor data from within the wellbore including the bottom hole assembly. The injectors, hauler, and carousel or reel can be driven by electric and / or hydraulic motors. In an instance, a Bowden tube is used to control the trajectory of the coiled tubing between the carousel and the injectors. This prevents the potential for the elastic coiled tubing to whip in the event of a fracture.

[0030] In some instances control system 360 (or another suitable control system of the present disclosure) is a real-time automated control system designed to protect and optimize the use of composite coiled tubing by, for example, controlling axial force to prevent slack-off and buckling, managing annular temperature to prevent overheating of the composite structure, coordinating surface and downhole components using sensor feedback and a physics-based digital twin. The system can integrate mid-string sensor nodes and a supervisory automation controller to provide closed-loop, predictive control over fluid circulation, pipe conveyance, and downhole actuation.

[0031] In some instances the automated control system can interface with and control fluid pumps to, for example, modulate flow rates to regulate heat transfer in the annulus, support forward or reverse circulation depending on the application, and maintain target fluid parameters (for example, density, temperature, and heat capacity).

[0032] In some instances the automated control system can interface with and control a pipe conveyance system (for example, injectors or tensioners) to, for example, provide axial movement and force control along the string, maintain proper weight on bit and prevents string buckling or over-pull, accommodate any gripper configuration, and reacts to real-time changes in tension, temperature, and pressure.F&R Ref. 50511 -0094 WO1

[0033] In some instances the automated control system can interface with and control carousels and reels, by, for example, managing storage, unspooling, and slack compensation for the composite string, and dynamically adjusting for thermal expansion / contraction over time.

[0034] In some instances the automated control system can interface with and control downhole tools. For example, the system can control valves, nozzles, or actuators within the coiled tubing string, manage flow redistribution, annular cooling, and pressure relief. The control system can allow thermal regulation based on local temperature feedback.

[0035] An event that can serve as an example use case can be as follows: when circulation stops, the internal pressure within the composite coiled tubing equalizes with the surrounding annular pressure, eliminating radial constraint. Concurrently, thermal soak from the formation raises the string’s temperature, triggering further expansion. Together, these effects can cause the string to lengthen by as much as 5% over several minutes. If this is not actively managed, it may result in, for example, loss of bit contact or excessive weight on bit (WOB), string buckling or slack in the wellbore, and / or strain on reels, injectors, or surface handling equipment. Distributed sensor inputs and digital twin modeling can be used to predict and compensate for these behaviors in real time, adjusting circulation, axial tension, and pipe feed rate to keep the system within safe mechanical and thermal limits.

[0036] Coiled tubing injection rate can be determined based on several factors including maintaining a desired weight on bit while drilling, the rate of penetration of the bit, the buckling behavior of the composite coiled tubing, the linear thermal expansion of the coiled tubing string, the stretch of the coiled tubing string. Similarly, coiled tubing retraction rate can be determined by one or more factors such as a desired time to surface, debris transport parameters while performing wiper trips, the linear thermal expansion of the coiled tubing string, the stretch of the coiled tubing string, pressure within the coiled tubing string, and the tensile properties of the coiled tubing. Coiled tubing tripping rates and applied string weight can be determined by a digital twin to the wellbore based on numeric modeling, real time sensor data from the rig, real time sensor data from instrumentation of the coiled tubing string, and real time sensor data from within the wellbore including the bottom hole assembly. In some instances, tubing may shorten axially when internal pressure is applied. This effect can vary along the length or the tubing as internal pressure decreases from top to bottom (i.e., friction pressure is dominant). The sensors can assis the digitalF&R Ref. 50511 -0094 WO1 twin to calculate true string length and the control system can run the string in or out of the wellbore to maintain a target weight-on-bit while drilling.

[0037] In this disclosure, “approximately” or “substantially” means a deviation or allowance of up to 10 percent (%) and any variation from a mentioned value is within the tolerance limits of any machinery used to manufacture the part. Likewise, “about” can also allow for a degree of variability in a value or range, for example, within 10%, within 5%, or within 1% of a stated value or of a stated limit of a range.

[0038] Values expressed in a range format should be interpreted in a flexible manner to include not only the numerical values explicitly recited as the limits of the range, but also to include all the individual numerical values or sub-ranges encompassed within that range as if each numerical value and sub-range is explicitly recited. For example, a range of “0.1% to about 5%” or “0.1% to 5%” should be interpreted to include about 0.1% to about 5%, as well as the individual values (for example, 1%, 2%, 3%, and 4%) and the sub-ranges (for example, 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the indicated range. The statement “X to Y” has the same meaning as “about X to about Y,” unless indicated otherwise. Likewise, the statement “X, Y, or Z” has the same meaning as “about X, about Y, or about Z,” unless indicated otherwise.

[0039] In this disclosure, the terms “a,” “an,” or “the” are used to include one or more than one unless the context clearly dictates otherwise. The term “or” is used to refer to a nonexclusive “or” unless otherwise indicated. The statement “at least one of A and B” has the same meaning as “A, B, or A and B.” In addition, it is to be understood that the phraseology or terminology employed in this disclosure, and not otherwise defined, is for the purpose of description only and not of limitation. Any use of section headings is intended to aid reading of the document and is not to be interpreted as limiting; information that is relevant to a section heading may occur within or outside of that particular section.

[0040] The term “uphole” as used herein means in the direction along a wellbore tubing string or the wellbore from its distal end (furthest from the surface) towards the surface, and “downhole” as used herein means the direction along a tubing string or the wellbore from the surface towards its distal end. A downhole location means a location along the tubing string or wellbore downhole of the surface.F&R Ref. 50511 -0094 WO 1

[0041] While this disclosure contains many specific implementation details, these should not be construed as limitations on the subject matter or on what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this disclosure in the context of separate implementations can also be implemented, in combination, or in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations, separately, or in any suitable sub-combination. Moreover, although previously described features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can, in some cases, be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.

[0042] Particular implementations of the subject matter have been described. Nevertheless, it will be understood that various modifications, substitutions, and alterations may be made. While operations are depicted in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed (some operations may be considered optional), to achieve desirable results. Accordingly, the previously described example implementations do not define or constrain this disclosure.

Claims

F&R Ref. 50511 -0094 WO1WHAT IS CLAIMED IS:

1. A carousel assembly for managing a length of wellbore tubing, the carousel assembly comprising: a stationary base; a hub rotatable relative to the stationary base about a central axis, the carousel assembly configured to, as the hub rotates, pay out the length of tubing from the hub to a wellhead; a hydraulic swivel configured to supply, as the hub rotates, fluid to a central bore of the length of tubing; and a connector configured to convey, as the hub rotates, a signal to a communication line extending axially along the length of tubing.

2. The carousel assembly of claim 1, wherein the hub is a cage.

3. The carousel assembly of either claim 1 or claim 2, wherein the connector is a first connector, the signal is a first signal, and the communication line is a first communication line, and wherein the carousel assembly further comprises a second connector configured to convey, as the hub rotates, a second signal to a second communication line extending axially along the length of tubing.

4. The carousel assembly of any one of claims 1 to 3, wherein the tubing is composite coiled tubing.

5. The carousel assembly of any one of claims 1 to 4, wherein the communication line comprises an electrical conveyance and the signal comprises an electrical signal.F&R Ref. 50511 -0094 WO16. The carousel assembly of claim 5, wherein the connector comprises an electrical contact ring.

7. The carousel assembly of any one of claims 1 to 6, wherein the communication line comprises a capillary tubing.

8. The carousel assembly of any one of claims 1 to 7, wherein the communication line comprises an optical fiber.

9. The carousel assembly of any one of claims 1 to 8, wherein the central axis is substantially vertical.

10. The carousel assembly of any one of claims 1 to 9, wherein the hub rotates on rollers disposed between the stationary base and the hub.

11. A well system comprising: a length of wellbore tubing configured to be disposed in a wellbore via a wellhead; and a carousel assembly within which a portion of the length of wellbore tubing is disposed, the carousel assembly comprising: a stationary base; a hub rotatable relative to the stationary base about a central axis, the carousel assembly configured to, as the hub rotates, pay out the length of tubing from the hub to the wellhead; and a hydraulic swivel configured to supply, as the hub rotates, fluid to a central bore of the length of tubing; and a connector configured to convey, as the hub rotates, a signal to a communication line extending axially along the length of tubing.F&R Ref. 50511 -0094 WO 112. The well system of claim 11, wherein the length of tubing comprises segments of tubing attached by a connector having a diameter greater than a diameter of the segments of tubing, and wherein the system further comprises a stripper assembly disposed between the hub and the wellhead, the stripper assembly comprising a first stripper spaced apart from a second stripper, the system configured to dilate the first stripper to permit the connector to pass through the first stripper while the second stripper seals about a peripheral surface of the length of tubing and thence, as the first stripper then closes to seal about the peripheral surface, dilate the second stripper to permit the connector to pass through the second stripper.

13. The well system of claim 11 or 12, wherein the hub is a cage.

14. The well system of any one of claims 11 to 13, wherein the length of tubing comprises segments of tubing attached by a connector having a diameter greater than a diameter of the segments of tubing, and wherein the system further comprises an injector assembly disposed between the hub and the wellhead, the injector assembly comprising a first injector spaced apart from a second injector, the system configured to dilate the first injector to permit the connector to pass through the injector while the second injector maintains the load of the tubing by contacting a peripheral surface of the tubing and thence, as the first injector then closes to maintains a load of the tubing by contacting a peripheral surface of the tubing, dilate the second injector to permit the connector to pass through the second injector.

15. The well system of any one of claims 11 to 14, wherein the communication line is configured to convey a signal to an apparatus disposed on a downhole portion of the length of tubing.F&R Ref. 50511 -0094 WO 116. The well system of claim 15, wherein the apparatus is a contactless drill bit.

17. The well system of any one of claims 10 to 16, wherein the system is controlled by an autonomous control system.

18. A method of well operations, the method comprising: disposing a portion of a length of tubing in a wellbore through a wellhead from a carousel assembly, the carousel assembly comprising: a stationary base; a hub rotatable relative to the stationary base about a central axis, the carousel assembly configured to, as the hub rotates, pay out the length of tubing from the hub to the wellhead; and a hydraulic swivel configured to supply fluid to a central bore of the length of tubing; and a connector configured to convey a signal to a communication line extending axially along the length of tubing; and as the hub rotates: flowing fluid through the central bore via the hydraulic swivel; and conveying a signal through the communication line.

19. The method of claim 18, wherein the hub is a cage.F&R Ref. 50511 -0094 WO120. The method of claim 18 or 19, wherein the connector is a first connector, the signal is a first signal, and the communication line is a first communication line, and wherein: the carousel assembly further comprises a second connector configured to convey, as the hub rotates, a second signal to a second communication line extending axially along the length of tubing; and the method further includes conveying the second signal through the second communication line.

21. The method of any one of claims 18 to 20, wherein the tubing is composite coiled tubing.

22. The method of any one of claims 18 to 21, wherein the communication line comprises an electrical conveyance, the signal comprises an electrical signal, and the connector comprises an electrical contact ring.

23. The method of any one of claims 18 to 22, wherein the length of tubing comprises segments of tubing attached by a connector.

24. The method of claim 23, wherein the connector has a diameter greater than a diameter of the segments of tubing.F&R Ref. 50511 -0094 WO125. The method of claim 23, wherein the system further comprises a stripper assembly disposed between the hub and the wellhead, the stripper assembly comprising a first stripper spaced apart from a second stripper, the method further comprising: dilating the first stripper to permit the connector to pass through the first stripper while the second stripper seals about a peripheral surface of the length of tubing; and thence, as the first stripper then closes to seal about the peripheral surface, dilating the second stripper to permit the connector to pass through the second stripper.

26. The method of claim 23, wherein the system further comprises a stripper assembly disposed between the hub and the wellhead, the stripper assembly comprising a first stripper spaced apart from a second stripper, the method further comprising: dilating the second stripper to permit the connector to pass through the second stripper while the first stripper seals about a peripheral surface of the length of tubing; and thence, as the second stripper then closes to seal about the peripheral surface, dilating the first stripper to permit the connector to pass through the first stripper.

27. The method of any one of claims 23 to 26, wherein the system further comprises an injector assembly disposed between the hub and the wellhead, the injector assembly comprising a first injector spaced apart from a second injector, the method further comprising, as the length of tubing is run into the wellbore: dilating the first injector to permit the connector to pass through the first injector while the second injector maintains the load of the tubing by contacting a peripheral surface of the tubing; and thence, as the first injector then closes to maintains the load of the tubing by contacting a peripheral surface of the tubing, dilating the second injector to permit the connector to pass through the second injector.F&R Ref. 50511 -0094 WO128. The method of any one of claims 23 to 26, wherein the system further comprises an injector assembly disposed between the hub and the wellhead, the injector assembly comprising a first injector spaced apart from a second injector, the method further comprising, as the length of tubing is run into the wellbore: dilating the second injector to permit the connector to pass through the second injector while the first injector maintains the load of the tubing by contacting a peripheral surface of the tubing; and thence, as the second injector then closes to maintains the load of the tubing by contacting a peripheral surface of the tubing, dilating the first injector to permit the connector to pass through the first injector.

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